In place of a deed , co-op members are granted shares of stock and a proprietary lease or occupancy agreement. A proprietary lease governs all aspects of the relationship between the co-op and each shareholder. With a conventional mortgage, the property is collateral for the loan.
With a cooperative mortgage or a share loan, the shares in the co-op corporation and the proprietary lease are the collateral. At the same time, they are tenants of the corporation that owns the property, placing them in the unique legal position of being both landlords and tenants.
A proprietary lease is considered to be a form of residential lease like any other. As a result, the relationship between the co-op and members is governed by the laws applicable to residential leases: landlord-tenant law. Buying into a co-op does come with strings attached. Before signing a proprietary lease, prospective investors must sit before a co-op board to be vetted. Additionally, a certain financial threshold, usually including a minimum gross income , must be also achieved in addition to an expressed intent to occupy the units for a specific period of time.
Considering a lease of your own? Use our lease calculator to determine your monthly payments. Several methods can be used to evaluate the presence of damage: production history plots that show sudden change, slope change, and gradual change; offset well comparison; pressure buildup tests; and well performance analysis.
Well testing and well test analysis generate a skin factor and well completion efficiency. This is insufficient alone for formation damage diagnosis. Well performance analysis has provided a beneficial tool to identify the location and thickness of damage at flow points in the near wellbore area. Models of flow into perforations and gravel-packed tunnels provide a way to relate the location and severity of damage to the completion procedure that preceded it.
Well diagnosis is not just an evaluation of whether a well is damaged. Picking a potentially successful acidizing candidate involves not only the fact that a well is damaged but what kind of damage and where it is located around the wellbore.
Damage is often most severe and localized at the point of flow entry into the wellbore. The improvement in damage analysis through well performance is rather recent, as evidenced by the work of several authors.
Some of this work has focused on identifying specific damage mechanisms. To select the appropriate acid, one must diagnose the probable type of damage and the extent of penetration into the formation.
Drilling solid infiltration is shallow less than one in. Perforation damage is shallow and varies in severity according to the perforating procedure. Water injection well damage can be quite deep when moderately clean fluids are injected over long periods of time with small unfiltered solids in the fluid.
Likewise, incompatible fluids may precipitate deeper in the formation. Repeated acid treatments also may leave damage deeper in the formation. Shallow damage can be quite severe in that thin filter cakes or internal bridging under high differential pressure can have very low permeability. Deep damage is usually more moderate but can be quite difficult to reach with reactive fluids like acid and, thus, may require deep treatments like hydraulic fracturing or acid fracturing.
Familiarity with all sources of damage and damaging operations is a requisite tool for an engineer selecting the best remedial acid treatment and is beyond the scope of this chapter.
Sparlin and Hagen [21] provide good information on damage mechanisms and damage analysis in their SPE Short Course on formation damage. McLeod [1] provides a damage check list.
More information on damaging mechanisms and analysis is provided in the chapter on formation damage in this handbook. Recent examples of damage analysis and removal are provided by Fambrough et al. Even though damage has been identified and an appropriate acid or other cleaning agent is available to remove the damage, one must evaluate the probable response of the formation its fluids and minerals to either the acid or spent acid.
There are many incompatibilities possible in acidizing various formations. These incompatibilities result in solid precipitates, which can plug pore throats so as to offset the improvement by acid dissolving pre-existing, damaging solids. Results can range from no bad effects and complete cleanup of damage to less than optimum improvement to plugging of the formation with acid-generated precipitates.
Post-treatment analysis showed that production was restricted by the small perforations small inflow area created with a through-tubing gun in underbalanced perforating; however, no permeability damage was present. Subsequent detailed petrographic core analysis indicated that a combination of acid-released fines and spent-acid precipitates damaged the formation during the acid treatment.
Such incompatibilities are discussed next. One can prevent acid-induced damage by predicting and dealing with formation response before acidizing. While it is sometimes easy to dissolve plugging solids, the real test of success is dissolving the solids without injecting or creating other damaging solids in the process. If potential incompatibilities between acid and formation solids or fluids are identified, precipitation of reaction products in the formation can be prevented or controlled.
Three properties of the formation are important: 1 Formation fluid analysis helps select appropriate displacement fluids to isolate formation fluids that are incompatible with either the acid or the spent acid products. Formation fluid compatibility with both acid and spent acid must be considered in the treatment with acid.
Formation water analysis is a standard test in laboratories, and chromatography is standard to identify gas compositions. Crude-oil analysis is much more complicated, so emulsion tests and sludge tests have been developed to identify incompatible crude oils.
High sulfate-ion content exists in some formation waters. Spending HCl acid on carbonate generates a high concentration of calcium ions, which precipitates calcium sulfate when spent acid mixes with formation water containing more than 1, ppm sulfate ion.
This can be prevented by preflushing the formation water away from the wellbore. In limestone acidizing, KCl or NaCl brines will work. Such a preflush, combined with quick return of spent acid from the formation by swabbing, has improved response to acidizing in the San Andres dolomite formation in eastern New Mexico.
High bicarbonate-ion content in formation waters causes precipitation of acid-dissolved scale. Treatment with an acid form of EDTA both removes calcium carbonate scale and prevents the recurrence of the scale for several months.
Sometimes sludge preventers and emulsion breakers cannot prevent the formation of stable emulsions. Dissolved iron also creates more stable sludge and emulsions with these crude oils.
Some difficult crudes need a preflush buffer of hydrocarbon solvent between crude oil and acid that is mutually compatible with both the crude oil and the acid. The buffer reduces contact between acid and the oil and prevents or reduces the problems with sludge and emulsions. Asphaltene particles can precipitate during production, and aromatic solvents can loosen and partially or completely dissolve them and also help acid dissolve solids.
Presoaks with an aromatic solvent and producing back before acidizing have been helpful in treating wells drilled with oil-based mud.
Organic skin damage in oil-producing wells is a major factor in the loss of productivity and revenue. Better methods of problem identification and programs to remediate these problems have been developed in recent years. The potential sources of organic damage, problem identification test techniques, chemical selection, and application methods are discussed.
Sulfide scavengers are effective in preventing incompatibilities and precipitation of iron sulfide. Methods to control the precipitates caused by acidizing are acid staging, lower acid concentrations, and overflushing.
Calcium and sodium chloride workover brine also must be flushed away from the wellbore with HCl acid or ammonium chloride brine. Preflushes also displace and isolate incompatible formation fluids either brine or crude oil. Treat with an adequate volume of proper concentration HF acid. Less may be used where only shallow, moderate damage exists e. Concentrations of 0. In some low-permeability sandstone, HF concentrations as low as 0.
If in doubt, consider an acid response test on a typical core or a geochemical acidizing simulator. See Table 7. Once you determine that a well is a good candidate for matrix acidizing and have selected appropriate acids, you are ready to design the treatment.
Essentially, the design process is a systematic approach to estimating and calculating injection pressure and rate, volumes, and concentrations. Live HF acid usually penetrates only about 6 to 12 in. Effective acid diversion reduces acid volumes needed. Guidelines for proper concentrations are provided in Table 7.
The background for the acid-use guidelines in Table 7. These guidelines helped when no previous experience existed in acidizing a particular formation. Evaluated experience provides the most reliable information.
Acid flow tests with cores are reliable when long cores are used. Gdanski [43] recommends With more reactive clays and a higher carbonate content, acetic acid must be added to the acid mixtures to maintain a lower pH and reduce the amount of post-acid precipitation. The guidelines in Table 7. Some treatments are very successful, and some result in little or no change. Pore throat sizes in these moderate-permeability formations are small enough to screen dispersed, undissolved clay-sized fines or spent acid precipitates and cause internal pore plugging.
Recent research has helped to better define formation response to acids; however, as a practical matter, small hydraulic fracturing treatments are simpler and more cost-effective than matrix acidizing in some of these formations with permeability less than 50 md. The guidelines for low permeability less than 10 md were based on treatments in which breakdown with acid probably occurred to open damaged perforations.
The lower concentrations prevented massive precipitation in the formation and damage to the isolating cement yet were sufficient to clean up some perforation damage. Such treatments are probably obviated now by the advent of tubing-conveyed perforating.
Three RHF acids that are based on boric acid, aluminum chloride, and a phosphoric acid were examined recently with guidance for their use. These acid mixtures improved the performance of two Brazilian water-injection wells by removing deep clay damage. Several geochemical models exist today that provide guidance on acid type and concentration. The acidizing model of Thomas and Fannin [48] predicts dissolution of rock to increase porosity and permeability and incorporates the resistance of a diverting agent to ensure good acid coverage in a layered sandstone formation.
The model does not consider precipitation and relies on an expert system to choose appropriate acid types and concentrations. The model of Davies et al. It also predicts the porosity decrease by precipitation of species and the final permeability of the rock around the wellbore as a result of net dissolution.
It helps select the volumes of acid required and the optimum acid types and concentrations to maximize well performance. Quinn et al. A new permeability prediction model relates the permeability of a permeable medium to the porosity, grain-size distribution, and the amounts and identities of all detrital minerals present and predicts productivity improvement.
The optimal matrix stimulation is a compromise between maximizing the dissolution of the damaging minerals and minimizing secondary precipitation. An integrated matrix stimulation model by Bartko et al. This perforation wash tool allows selective injection of acid into closely spaced perforations in high-permeability formations.
High pressures can cause the cups to leak or turn over or the tool to separate at the port the weakest part. High pressure can also establish communication behind the pipe between the point of injection and nearby perforations without removing damage from the plugged perforation. This type of isolation is best used for removing damage from severely plugged perforations in high-permeability formations. A good method of isolating perforated intervals is to use a retrievable bridge plug and a squeeze packer.
The bridge plug is set in blank sections of casing between perforated sections. The treatment usually begins with the lower set of perforations and finishes with the upper set. Straddle packers may be used in a similar way and have been used successfully in the Permian Basin to better clean damaged perforations. Ball sealers can be divided into two categories: those heavier sinkers and those lighter floaters than the fluid. Successful use requires a good cement job on the installed casing and round good quality perforation holes.
The high pump rate usually prohibits their use in sandstone matrix acidizing, but they may be used in fracture acidizing or perforation breakdown. The density or specific gravity of these ball sealers is matched to the fluid being pumped so better ball action will take place. Surface flowback equipment must be modified to catch the floating ball sealers during flowback.
Ball sealers are limited in their use. Regardless of the type of treatment or ball used, treatment will be more effective when density of the ball is very close to the density of the fluid used in the treatment.
One effective way to divert acid in a treatment before gravel packing is to use slugs of hydroxyethylcellulose HEC gel and gravel-pack sand. The combination of viscosity and sand packing helps divert acid to other perforations. The unique feature of this method, as opposed to other "particulate diverters," is that the perforation tunnel is packed with gravel-pack sand instead of some other material that would prevent gravel-pack slurry from entering the perforations during later slurry placement.
Thickening the acid through use of soluble polymers, nitrogen and foaming agents, or dispersing oil either as loose two-phase mixtures or with emulsifiers is useful in high-permeability formations with deep damage. Design is difficult; therefore, experience and on-site flexibility are important for success.
Excellent results have been obtained with staged foam slugs between acid stages in high-permeability Gulf Coast gas wells to remove near-wellbore damage. This technique is so promising because the diverter gas and fluid disappears when the foam breaks with little chance of damage as with slowly dissolving particulates. See Gdanski and Behanna [52] for useful guidelines. Fadele et al. Water and acid are times more viscous than gas, and this provides a natural diversion for acid entering a gas formation.
This may be one reason acidizing works better in gas wells than in oil wells. Other recent papers offer further improvements with viscous acids and diverters. Rathole fluid should be heavier than the acid, and fluid above the top perforation should be lighter than the acid. If not, acid can end up in the rathole rather than the formation. Acid left in the borehole can cause casing leaks below the treated interval.
Spotting acid over the perforations before injecting is very important in low to moderate permeability 10 to 50 md , and density segregation must be planned to achieve the best contact of acid with damaged perforations in these formations. Concentric tubing helps to achieve accurate placement of the acid in the wellbore to take advantage of density segregation.
Concentric tubing is preferred for matrix acid treatments because it allows the rathole to be circulated clean, permits better placement for acid contact with all perforations, bypasses production or injection tubing debris, can be acid cleaned on surface before running into the hole, and limits pump rate to 0.
The design and implementation of diverting systems has been advanced by recent design techniques but still relies on guidelines and field experience. Hill and Rossen [57] have provided a better means to compare diverting methods and design diverting treatments. Gdanski and Behenna [52] have provided some appropriate guidelines for foamed acids or foamed-diverter stages. Hill and Rossen compared the techniques of injection rate diversion, coined MAPDIR maximum pressure differential and injection rates ; particulate diverting agents; viscosified fluids; and foamed acid.
MAPDIR results in effective treatment of lower-permeability layers but at the expense of much larger volumes of acid. It may also be limited in use by pump and tubing capacities. Wells can clean up faster because no particulates are used. Also, treatment time is less to achieve the same reduction in skin factor as other techniques. The particulate diverting is most efficient in terms of volumes of acid and, thereby, is generally more economic if treating time is not a large economic factor.
Oil soluble resins are not completely oil soluble, and sometimes plugging by these resins may not be temporary. Quality assurance is the pretreatment planning to ensure that proper materials and procedures are used. Quality control is on-site supervision and testing to ensure that quality treatment is performed.
Foam diversion is nondamaging in that surfactants are soluble and removable in produced water and nitrogen is recovered. Foams are most difficult to design and are not completely understood in terms of their behavior in different formations; however, guidelines for designing and implementing foam treatments are provided by Gdanski and Behenna.
They also tend to be more stable in water zones and less stable in oil layers, providing some selectivity in treating wells with high water cuts or nearby bottom water. Viscosified fluids are similar to foam but provide a more consistent fluid hydrostatic pressure when well pressure limitations are present. The viscous behavior of these fluids in different formations is not well defined.
Horizontal wells are special cases, which have been covered by Frick and Economides. Moderate damage can reduce horizontal well productivity to that below the productivity of an undamaged vertical well. The authors provide a stimulation technique employing coiled tubing.
They also provide a design strategy for calculating volumes of acid required and the rate of coiled-tubing withdrawal during acid placement. A method of optimization for completion and stimulation of horizontal wells is also presented. Other papers have further advanced the planning, design, diversion, execution, and evaluation of acidizing horizontal wells employing similar methods to those used in vertical wells.
An acid additive is any material blended with acid to modify its behavior. Because acid is so naturally corrosive, the development of an additive to reduce acid attack on steel pipe was the first requirement for successful acidizing. Development of a suitable corrosion inhibitor started the acidizing service industry in Comprehensive testing and application of corrosion inhibitors is still necessary in successful acidizing.
Many acid additives are available, but those that are usually necessary are corrosion inhibitors, surfactants, and iron control agents. Any other additives are optional and should not be used unless specific well conditions dictate their use and have been thoroughly tested for compatibility with the formation fluids and the necessary additives.
A mutual solvent in the overflush may be beneficial. By nature of its adsorption on solid surfaces, the corrosion inhibitor is a surface-active agent with a unique purpose—to protect pipe rather than to change acid behavior in the formation. Corrosion inhibitors do not stop corrosion; they greatly reduce the reaction rate of acid with steel. Proper selection and application of corrosion inhibitors also reduce pitting the tendency of acid to corrode or dissolve metal deeply in specific sites.
Corrosion inhibitors are cationic and oil wetters. This is the mechanism by which they adsorb plate out on a metal surface and form an oil-wet film to protect the iron from exposure to acid. Plating out and oil wetting also occur in the formation, especially on clay minerals. To compensate for this, other additives, such as surfactants and mutual solvents, are used to restore water-wetness and maximize permeability to oil. Pitting corrosion is very detrimental to the integrity of pipe.
Reasons for pitting are inhibitor breakdown with time and temperature, insufficient inhibitor for wellbore conditions, and metal impurities in pipe. Factors that affect corrosion are pipe metallurgy, type acid, acid concentration, temperature, inhibitor solubility in the acid, inhibitor concentration, contact time with steel, inhibitor aids, and compatibility with other acids and additives such as organic acid, surfactants, alcohol, and solvent in the acid.
Service companies perform extensive lab testing in combination with additives to provide data to estimate the time of protection of pipe during the course of acid exposure to tubing in an acid treatment. The type of inhibitors and conditions in which they are used are many and complex. Usually, less than 5 mils of tubing corrosion should be allowed by the inhibitor in an acid treatment equivalent to 0.
Surface active agents are molecules composed of an oil-soluble group and a water-soluble group. These chemicals lower the interfacial tension between the immiscible fluids. They also adsorb on rock surfaces and can alter the natural wettability of rock. Surfactants are classified into four major groups depending on the nature of the water-soluble part of the molecule.
These divisions are anionic water-soluble end is anionic , cationic water-soluble end is cationic , nonionic do not ionize—one end of molecule is water-soluble, the other is oil-soluble , and amphoteric water-soluble end may be anionic, cationic, or uncharged depending on the pH of the system. Other uses are as wetting agents, penetrating agents, sludge preventers and foaming agents, acid solvent dispersant, mud dispersants, emulsion breakers, retarders, and suspending agents.
Iron control uses several different products to keep iron in solution: iron complexing agents, iron reducing agents, and hydrogen sulfide scavengers. Iron in solution has two forms: ferric and ferrous. The oxidized form, iron III , precipitates in spent acid around a pH of 1 to 2. Iron II does not precipitate as ferrous hydroxide until a pH of 7 is reached, well beyond the final equilibrium of spent HCl acid, which is around a pH of 5.
Normally, the ferrous iron is not a problem in acid treatments; however, there are three exceptions. Assignment of Agreements means, with respect to the Property, that certain first priority Assignment of Agreements, Licenses, Permits and Contracts dated as of the date hereof, from Borrower, as assignor, to Lender, as assignee, assigning to Lender as security for the Loan, to the extent assignable under law, all of Borrower's interest in and to the Management Agreements and all other licenses, permits and contracts necessary for the use and operation of the Property, as the same may be amended, restated, replaced, supplemented or otherwise modified from time to time.
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